SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

(Mark One)

 

 

Commission file number 1-10389

 

WESTERN GAS RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 under the Exchange Act). Yes ý  No  o

 

On May 1, 2003, there were 33,162,506 shares of the registrant’s Common Stock outstanding.

 

 

Western Gas Resources, Inc.

Form 10-Q

Table of Contents

 

PART I - Financial Information
	Item 1.	Financial Statements
		Consolidated Balance Sheet - March 31, 2003 and December 31, 2002
		Consolidated Statement of Cash Flows - Three Months Ended March 31, 2003 and 2002
		Consolidated Statement of Operations - Three Months Ended March 31, 2003 and 2002
		Consolidated Statement of Changes in Stockholders’ Equity - Three Months Ended March 31, 2003
		Notes to Consolidated Financial Statements
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk
	Item 4.	Controls and Procedures
PART II - Other Information
	Item 1.	Legal Proceedings
	Item 6.	Exhibits and Reports on Form 8-K
Signatures

 

2

 

PART I - - FINANCIAL INFORMATION

 

ITEM 1.          FINANCIAL STATEMENTS

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Dollars in thousands, except share data)

 

		March 31, 2003			December 31, 2002
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	13,188		$	7,312
Trade accounts receivable, net		426,880			253,587
Inventory		23,217			43,482
Assets held for sale		4,369			3,250
Assets from price risk management activities		26,244			34,873
Other		3,250			27,744
Total current assets		497,148			370,248
Property and equipment:
Gas gathering, processing, storage and transportation		995,946			942,147
Oil and gas properties and equipment (successful efforts method)		270,831			252,747
Construction in progress		98,424			104,033
		1,365,201			1,298,927
Less:  Accumulated depreciation, depletion and amortization		(453,629		)	(432,281		)
Total property and equipment, net		911,572			866,646
Other assets:
Gas purchase contracts (net of accumulated amortization of $37,572 and $37,232, respectively)		30,583			30,924
Assets from price risk management activities		939			406
Other		32,348			33,920
Total other assets		63,870			65,250
TOTAL ASSETS		$	1,472,590		$	1,302,144
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	421,515		$	242,987
Accrued expenses		42,539			51,509
Liabilities from price risk management activities		39,552			34,811
Dividends payable		3,469			3,464
Total current liabilities		507,075			332,771
Long-term debt		309,833			359,933
Liabilities from price risk management activities		914			406
Other long-term liabilities		20,583			1,713
Deferred income taxes payable, net		134,127			124,253
Total liabilities		972,532			819,076
Stockholders’ equity:
Preferred Stock; 10,000,000 shares authorized:
$ 2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued ($138,000,000 aggregate liquidation preference)		276			276
Common stock, par value $.10; 100,000,000 shares authorized; 33,153,541 and 33,077,611 shares issued, respectively		3,336			3,329
Treasury stock, at cost; 25,016 common shares in treasury		(788		)	(788		)
Additional paid-in capital		382,474			381,066
Retained earnings		122,198			102,292
Accumulated other comprehensive income		(7,143		)	(2,812		)
Notes receivable from key employees secured by common stock		(295		)	(295		)
Total stockholders’ equity		500,058			483,068
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	1,472,590		$	1,302,144

 

The accompanying notes are an integral part of the consolidated financial statements.

 

3

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

		Three Months Ended March 31,
		2003			2002
Reconciliation of net income to net cash provided by operating activities:
Net income		$	23,375		$	8,000
Add income items that do not affect cash:
Depreciation, depletion and amortization		18,143			17,946
Gain on the sale of property and equipment		281			9
Deferred income taxes		17,183			3,836
Non-cash change in fair value of derivatives		4,163			10,995
Cumulative effect of change in accounting principle		6,724			—
Other non-cash items, net		2,208			(27		)
Adjustments to working capital to arrive at net cash provided by operating activities:
Increase in trade accounts receivable		(173,095		)	(15,476		)
Decrease in product inventory		20,308			25,851
Decrease in other current assets		26,797			651
Increase in other assets and liabilities, net		(343		)	(71		)
Increase (decrease) in accounts payable		178,528			(36,009		)
Increase (decrease) in accrued expenses		(9,117		)	6,820
Net cash provided by operating activities		115,155			22,525
Cash flows from investing activities:
Purchases of property and equipment		(57,076		)	(26,896		)
Proceeds from the dispositions of property and equipment		41			32
Contributions to equity investees		—			(4,702		)
Net cash used in investing activities		(57,035		)	(31,566		)
Cash flows from financing activities:
Proceeds from exercise of common stock options		1,268			5,477
Payments on revolving credit facility		(391,800		)	(279,400		)
Borrowings on long-term debt		25,000			—
Borrowings under revolving credit facility		316,700			282,600
Debt issue costs		(95		)	—
Effect of re-priced options		147			343
Dividends paid		(3,464		)	(3,767		)
Net cash provided by (used in) financing activities		(52,244		)	5,253
Net increase (decrease) in cash and cash equivalents		5,876			(3,788		)
Cash and cash equivalents at beginning of period		7,312			10,032
Cash and cash equivalents at end of period		$	13,188		$	6,244

 

The accompanying notes are an integral part of the consolidated financial statements.

4

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

(Dollars in thousands, except share and per share amounts)

 

		Three Months Ended March 31,
		2003			2002
Revenues:
Sale of gas		$	779,739		$	545,589
Sale of natural gas liquids		92,049			64,807
Gathering, processing and transportation revenue		19,777			15,431
Non-cash change in fair value of derivatives		(4,163		)	(10,995		)
Other		704			1,083
Total revenues		888,106			615,915
Costs and expenses:
Product purchases		771,602			544,606
Plant and transportation operating expense		21,922			18,871
Oil and gas exploration and production expense		12,511			7,389
Depreciation, depletion and amortization		18,143			17,946
(Gain) loss on sale of assets		281			9
Selling and administrative expense		10,592			8,691
Earnings from equity investments		(1,562		)	(851		)
Interest expense		6,814			6,660
Total costs and expenses		840,303			603,321
Income before taxes		47,803			12,594
Provision for income taxes:
Current		521			758
Deferred		17,183			3,836
Total provision for income taxes		17,704			4,594
Income before Cumulative effect of change in accounting principle		30,099			8,000
Cumulative effect of change in accounting principle, net of tax benefit of $3,967		(6,724		)	—
Net income		23,375			8,000
Preferred stock requirements		(1,811		)	(2,130		)
Income attributable to common stock		$	21,564		$	5,870
Net income per share of common stock before cumulative effect of a change in accounting principle
		$	.85		$	.18
Cumulative effect of a change in accounting principle		$	.20		$	—
Earnings per share of common stock		$	.65		$	.18
Weighted average shares of common stock outstanding		33,087,680			32,760,081
Income attributable to common stock - assuming dilution		$	23,375		$	5,870
Earnings per share of common stock - assuming dilution		$	.63		$	18
Weighted average shares of common stock outstanding - assuming dilution		37,163,098			33,457,239

 

The accompanying notes are an integral part of the consolidated financial statements.

 

5

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, except share amounts)

 

		$ 2.625 Cumulative Convertible Preferred Stock		Shares of Common Stock		Shares of Common Stock in Treasury		$ 2.625 Cumulative Convertible Preferred Stock			Common Stock			Treasury Stock			Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income Net of Tax			Notes Receivable from Key Employees			Total Stock- holders' Equity
Balance at December 31, 2002		2,760,000		33,077,611		25,016		$	276		$	3,329		$	(788	)	$	381,066		$	102,292		$	(2,812	)	$	(295	)	$	483,068
Comprehensive income:
Net income, three months ended March 31, 2003		—		—		—		—			—			—			—			23,375			—			—			23,375
Translation adjustments		—		—		—		—			—			—			—			—			582			—			582
Reclassification adjustment for settled contracts		—		—		—		—			—			—			—			—			1,669			—			1,669
Changes in fair value of outstanding hedging positions		—		—		—		—			—			—			—			—			(6,548		)	—			(6,548		)
Reduction due to estimated ineffectiveness		—		—		—		—			—			—			—			—			(34		)	—			(34		)
Change in accumulated derivative comprehensive income		—		—		—		—			—			—			—			—			(4,913		)	—			(4,913		)
Total comprehensive income, net of tax																													19,044
Stock options exercised		—		75,930		—		—			7			—			1,261			—			—			—			1,268
Effect of re-priced stock options		—		—		—		—			—			—			147			—			—			—			147
Dividends declared on common stock		—		—		—		—			—			—			—			(1,658		)	—			—			(1,658		)
Dividends declared on $2.625 cumulative convertible preferred stock		—		—		—		—			—			—			—			(1,811		)	—			—			(1,811		)
Balance at March 31, 2003		2,760,000		33,153,541		25,016		$	276		$	3,336		$	(788	)	$	382,474		$	122,198		$	(7,143	)	$	(295	)	$	500,058

 

The accompanying notes are an integral part of the consolidated financial statements.

 

6

 

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

GENERAL

 

The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2002.  The interim consolidated financial statements as of March 31, 2003 and for the three month periods ended March 31, 2003 and 2002 included herein are unaudited but reflect, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to fairly present the results for such periods.  The results of operations for the three months ended March 31, 2003 are not necessarily indicative of the results of operations expected for the year ended December 31, 2003.

 

Prior period amounts in the interim consolidated financial statements and notes have been reclassified as appropriate to conform to the presentation used in 2003.

 

EARNINGS PER SHARE OF COMMON STOCK

 

Earnings per share of common stock are computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding.  In addition, earnings per share of common stock - assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares.  Income attributable to common stock is income less preferred stock dividends.  We declared preferred stock dividends of $1.8 million and $2.1 million for the three-month periods ended March 31, 2003 and 2002, respectively.  Common stock options and our $2.625 Cumulative Convertible Preferred Stock are potential common shares.  Outstanding common stock options in both three-month periods and our $2.625 Cumulative Convertible Preferred Stock, which is convertible into 3,471,698 shares of common stock, in the three months ended March 31, 2003, had a dilutive effect on earnings.  This resulted in an increase in the weighted average number of shares of common stock outstanding by 4,075,418 and 697,158 for the three-month periods ended March 31, 2003 and 2002, respectively.  The numerators and the denominators for these periods were adjusted to reflect these potential shares and any related preferred dividends in calculating fully diluted earnings per share.

 

ACCUMULATED OTHER COMPREHENSIVE INCOME

 

Included in Accumulated other comprehensive income at March 31, 2003 were unrealized losses of  $10.3 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $3.2 million of cumulative foreign currency translation adjustments.

 

Included in Accumulated other comprehensive income at March 31, 2002 were unrealized gains of $4.7 million from the fair value of derivatives designated as cash flow hedges and $1.9 million of cumulative foreign currency translation adjustments.

 

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

 

In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations.”  SFAS No. 143 is effective for fiscal years beginning after June 15, 2002.  SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost.  We adopted SFAS No. 143 on January 1, 2003 and recorded a $11.5 million increase to Property and Equipment, a $4.4 million increase to Accumulated depreciation, depletion and amortization, a $17.8 million increase to Other long-term liabilities and a $6.7 million non-cash, after-tax loss from the Cumulative effect of a change in accounting principle.

 

The following is a reconciliation of the asset retirement obligation for the three months ended March 31, 2003 (dollars in thousands):

 

 

7

 

Exclusive of assets disposed of during 2002, if we had adopted SFAS No. 143 as of January 1, 2002, we estimate that the asset retirement obligation at that date would have been $15.7 million, based on the same assumptions used in our calculation of the obligation at January 1, 2003.  The estimated 2002 pro forma effect of January 1, 2002 adoption of SFAS No. 143 on net income and earnings per share, for annual and interim periods, is not material.

 

In connection with the adoption of SFAS No. 143, we completed a review of our operating assets and reevaluated the operating life and salvage values of the associated equipment.  As a result of this evaluation, we extended the useful life of many of our operating assets and adjusted the estimated salvage value of our operating equipment.  These adjustments resulted in an approximate $2.5 million, or $0.04 per share of common stock - assuming dilution, decrease in depreciation, depletion and amortization in the three months ended March 31, 2003 from the expense calculated using the previous useful lives.  The adjustments to the salvage value and depreciable lives of our assets are treated as a revision of an estimate and will be accounted for on a prospective basis.

 

OTHER INFORMATION

 

Acquisition of Gathering Systems.  Effective February 1, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million.  These assets were acquired from El Paso Field Services, or EPFS, and related entities.  The three largest systems are located in the Wamsutter area of the Greater Green River Basin.   Four of these systems are located in the Wind River Basin and provide us with the opportunity to expand our gathering and processing activities into an area in which we have not previously operated.  Several of the systems located in the Powder River Basin do not integrate directly into our existing systems and will likely be disposed of.  These systems are classified as Assets held for sale on the Consolidated Balance Sheet at March 31, 2003.  During the first quarter of 2003, the facilities, which are included in Assets held for sale, generated net after-tax earnings of approximately $94,000, or $0.00 per share of common stock.  We believe the results from these facilities are immaterial for separate presentation as a discontinued operation.

 

Corporate Offices.  In August 2002, we entered into a lease with a seven year and nine month term for approximately 85,000 square feet of office space in Denver, Colorado.  The cumulative lease payments over the term of this agreement, which began upon occupancy, will total approximately $10.7 million.  Our corporate offices were relocated to this space in March 2003.  At March 31, 2003, the office building we previously occupied was reflected on the Consolidated Balance Sheet as an Asset held for sale.  We completed the sale of this building in April 2003.

 

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

 

The net loss recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the first three months of 2003 from hedging activities was $12.7 million.  Additionally, we recognized a net of a loss of $53,000 resulting from hedge ineffectiveness due to the use of crude oil swaps in hedging the variability in the sales price of normal butane.  Overall, our hedges are expected to continue to be “highly effective” under SFAS No. 133 in the future.  An additional $2.8 million of losses were reclassified into earnings as a result of the discontinuance of cash flow hedges.  These cash flow hedges were discontinued due to the reduction of forecasted production volumes.

 

The gains and losses currently reflected in Accumulated other comprehensive income will be reclassified to earnings based on the actual sales of the hedged gas or NGLs.  Based on prices as of March 31, 2003, approximately $10.3 million of losses in Accumulated other comprehensive income will be reclassified to earnings in the next nine months.

 

SUPPLEMENTARY CASH FLOW INFORMATION

 

Interest paid was $3.1 million and $3.0 million for the three months ended March 31, 2003 and 2002, respectively. A total of $4.9 million was paid in income taxes in the three months ended March 31, 2003.  No income taxes were paid during the three months ended March 31, 2002.

 

STOCK COMPENSATION

 

As permitted under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), we have elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.”  We have complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement.  We realize an income tax benefit from the exercise of non-qualified stock options related to the amount by which the market price at the date of exercise exceeds the option price.  This tax benefit is credited to additional paid-in capital.

 

We are required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which our stock price at the end of any quarter exceeds $21.00 per share.  We had re-priced options covering 59,500 common shares outstanding at March 31, 2003 and 78,000 common shares outstanding at March 31, 2002.  Based on our stock price at March 31, 2003 of $32.55 and our stock price at March 31, 2002 of $37.22 per share, compensation expense of $53,000 and $372,000 was recorded in the three months ended March 31, 2003 and 2002, respectively.

 

8

 

SFAS No. 123 encourages companies to record compensation expense for stock-based compensation plans at fair value.  As permitted under SFAS No. 123, we have elected to continue to measure compensation costs for such plans as prescribed by APB No. 25.  SFAS No. 123 requires pro forma disclosures for each quarter that a statement of operations is presented.  During the three months ended March 31, 2003, there were grants under the 2002 Plan.  During the three months ended March 31, 2002, there were no grants under any stock option plan.  The weighted average fair value of options granted during the first quarter of 2003 under the 2002 Plan was $18.28 per option.  This value was estimated using the Black-Scholes option-pricing model with the following assumptions:

 

 

If we had recorded compensation expense for our grants under our stock-based compensation plans consistent with the fair value method under SFAS No. 123, our net income, income attributable to common stock, earnings per share of common stock and earnings per share of common stock - assuming dilution would approximate the pro forma amounts below (dollars in thousands, except per share amounts):

 

		Three Months Ended March 31,
		2003			2003			2002			2002
		As Reported			Pro Forma			As Reported			Pro Forma
Net income		$	23,375		$	22,610		$	8,000		$	7,400
Net income attributable to common stock		21,564			20,799			5,870			5,270
Earnings per share of common stock		0.65			0.63			0.18			0.16
Earnings per share of common stock  - assuming dilution		0.63			0.61			0.18			0.16
Stock-based employee compensation cost, net of related tax effects, included in net income		$	92		$	—		$	295		$	—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied		$	—		$	857		$	—		$	895

 

The fair market value of the options at grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense.

 

SEGMENT REPORTING

 

We operate in four principal business segments, as follows:  Gas Gathering, Processing and Treating; Exploration and Production; Marketing; and Transportation.  Management separately monitors these segments for performance against our internal forecast and these segments are consistent with our internal financial reporting package.  These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations.

 

Gas Gathering, Processing and Treating.  In this segment, we connect producers’ wells (including those of the Exploration and Production segment) to our gathering systems for delivery to our processing or treating plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications.  In some areas, where no processing is required, we gather and compress producers’ gas and deliver it to pipelines.  Except for volumes taken in kind by our producers, the Marketing segment sells the residue gas and NGLs extracted at most of our facilities.  In this segment, we recognize revenue for our services at the time the service is performed.

 

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease.  Approximately 77% of our plant facilities’ gross margins, or revenues at the plants less product purchases, for the month of March 2003 resulted from percentage-of-proceeds agreements in which we are typically responsible for the marketing of the gas and NGLs. We pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

 

9

 

Approximately 19% of our plant facilities’ gross margins for the month of March 2003 resulted from contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling.

 

Approximately 4% of our plant facilities’ gross margins for the month of March 2003 resulted from contracts that combine gathering, compression or processing fees with ‘‘keepwhole’’ arrangements or wellhead purchase contracts. Typically, we charge producers a gathering and compression fee based upon volume. In addition, we retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The ‘‘keepwhole’’ component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

 

Exploration and Production.  The activities of the Exploration and Production segment include the exploration and development of gas properties primarily in the Rocky Mountain basins including those where our gathering and/or processing facilities are located.  The Marketing segment sells the majority of the production from these properties.

 

Marketing.  Our Marketing segment buys and sells gas and NGLs in the United States and Canada from and to a variety of customers.  The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price.   In addition, this segment also markets gas and NGLs produced by our gathering, processing, treating and production assets.  Also included in this segment are our Canadian marketing operations (which are immaterial for separate presentation).  In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities.  We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand.  Our gas sales contracts have an average duration of 15 months. 

 

Transportation.  The Transportation segment reflects the operations of Western’s MIGC and MGTC pipelines.  The majority of the revenue presented in this segment is derived from transportation of residue gas for our Marketing segment and other third-parties.  In this segment, we realize revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline.  The Transportation segments’ firm capacity contracts range in duration from one month to six years.

 

The following table sets forth our segment information as of and for the two quarters ended March 31, 2003 and 2002 (dollars in thousands).  Due to our integrated operations, the use of allocations in the determination of business segment information is necessary.  Inter-segment revenues are valued at prices comparable to those of unaffiliated customers.

 

		Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Quarter Ended March 31, 2003
Revenues from unaffiliated customers
Sale of gas		$	1,073		$	(283	)	$	786,412		$	296		$	—		$	—		$	787,498
Sale of natural gas liquids		4			—			96,937			—									96,941
Equity hedges:
Residue		(968		)	(6,791		)	—			—			—			—			(7,759		)
Liquids		(4,892		)	—			—			—			—			—			(4,892		)
Gathering, processing and transportation revenue		17,904			—			—			1,838			35			—			19,777
Total revenues from unaffiliated customers		13,121			(7,074		)	883,349			2,134			35			—			891,565
Inter-segment sales		301,769			64,544			11,031			3,875			34			(381,253		)	—
Non-cash change in fair value of derivatives		(724		)	(2,098		)	(1,341		)	—			—			—			(4,163		)
Interest income		—			8			—			2			2,422			(2,349		)	83
Other, net		431			29			—			—			161			—			621
Total revenues		314,597			55,409			893,039			6,011			2,652			(383,602		)	888,106
Product purchases		264,348			394			877,928			—			132			(371,200		)	771,602
Plant operating and transportation expense		19,974			178			80			1,965			531			(806		)	21,922
Oil and gas exploration and production expense		—			21,561			—			—			—			(9,050		)	12,511
Earnings from equity investments		(1,562		)	—			—			—			—			—			(1,562		)
Operating profit		31,837			33,276			15,031			4,046			1,989			(2,546		)	83,633
Depreciation, depletion and amortization		7,895			8,060			35			433			1,720			—			18,143
Selling and administrative expense		4,735			3,241			2,055			561			—			—			10,592
(Gain) loss from sale of assets		(92		)	—			—			—			373			—			281
Interest expense		—			—			—			—			6,814			—			6,814
Segment profit		$	19,299		$	21,975		$	12,941		$	3,052		$	(6,918	)	$	(2,546	)	$	47,803
Identifiable assets
Other allocated assets		$	(2,215	)	$	3,424		$	107,202		$	1,306		$	478,446		$	(51,330	)	$	536,833
Investment in others		2,914			—			—			3,731			53,714			(36,174		)	24,185
Capital assets		587,781			225,487			1,637			42,142			54,432			7			911,572
Total identifiable assets		$	588,480		$	228,911		$	108,839		$	47,179		$	586,592		$	(87,497	)	$	1,472,590

 

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		Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Quarter Ended March 31, 2002
Revenues from unaffiliated customers
Sale of gas		$	315		$	252		$	534,383		$	520		$	—		$	—		$	535,470
Sale of natural gas liquids		3			—			65,446			—			—			—			65,449
Equity hedges:
Residue		1,698			8,421			—			—			—			—			10,119
Liquids		(642		)	—			—			—			—			—			(642		)
Gathering, processing and transportation revenue		13,173			—			—			2,259			(1		)	—			15,431
Total revenues from unaffiliated customers		14,547			8,673			599,829			2,779			(1		)	—			625,827
Inter-segment sales		121,330			19,813			3,560			4,129			14			(148,846		)	—
Non-cash change in fair value of derivatives		—			—			(10,995		)	—			—			—			(10,995		)
Interest income		—			10			—			—			1,827			(1,800		)	37
Other, net		775			(17		)	—			12			276			—			1,046
Total revenues		136,652			28,479			592,394			6,920			2,116			(150,646		)	615,915
Product purchases		102,297			525			584,370			—			322			(142,908		)	544,606
Plant operating and transportation expense		16,425			56			53			2,615			—			(278		)	18,871
Oil and gas exploration and production expense		—			13,046			—			—			—			(5,657		)	7,389
Earnings from equity investments		(851		)	—			—			—			—			—			(851		)
Operating profit		18,781			14,852			7,971			4,305			1,794			(1,803		)	45,900
Depreciation, depletion and amortization		10,596			5,321			40			435			1,554			—			17,946
Selling and administrative expense		3,841			2,364			1,773			713			—			—			8,691
Loss from sale of assets		3			—			—			6			—			—			9
Interest expense		—			—			—			—			8,460			(1,800		)	6,660
Segment profit		$	4,341		$	7,167		$	6,158		$	3,151		$	(8,220	)	$	(3	)	$	12,594
Identifiable assets
Other allocated assets		$	8,001		$	6,169		$	98,528		$	1,111		$	306,023		$	(56,275	)	$	363,557
Investment in others		1,863			—			—			3,660			44,529			(37,637		)	12,415
Capital assets		571,230			191,215			1,790			42,833			52,924			—			859,992
Total identifiable assets		$	581,094		$	197, 384		$	100,318		$	47,604		$	403,476		$	(93,912	)	$	1,235,964

 

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LEGAL PROCEEDINGS

 

Reference is made to “Part II - Other Information - Item 1. Legal Proceedings,” of this Form 10-Q.

 

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

 

In April 2002, the FASB issued SFAS No. 145, “Rescission of FAS Statements No. 4, 44 and 64, Amendment of FAS Statement No. 13, and Technical Corrections,” which is generally effective for fiscal years beginning after May 15, 2002.  Through the rescission of SFAS Statements 4 and 64, SFAS No. 145 eliminates the requirement that gains and losses from extinguishment of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect.  SFAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice.  We adopted SFAS No. 145 on January 1, 2003.  The adoption of this pronouncement did not have an impact on our earnings or financial position as we had no gains and losses from extinguishment of debt in the first quarter of 2003.

 

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.”  SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002.  This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force, or EITF, Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity  (including Certain Costs Incurred in a Restructuring).”   We adopted SFAS No. 146 on January 1, 2003.  The adoption of this pronouncement did not have an impact on our earnings or financial position for the first quarter of 2003.

 

In November 2002, the FASB issued Interpretation No. 45, or “FIN 45”, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45 requires that a liability be recorded in the guarantor’s balance sheet upon issuance of a guarantee. FIN 45 also requires additional disclosures about the guarantees an entity has issued. We adopted FIN 45 on January 1, 2003.  The adoption of this pronouncement did not have an impact on our earnings or financial position in the first quarter of 2003.

 

In January 2003, the FASB issued Interpretation No. 46, or “FIN 46”, “Consolidation of Variable Interest Entities.”  FIN 46 provides guidance on how to identify a variable interest entity, or VIE, and determine when the assets, liabilities, and results of operations of a VIE need to be included in a company’s consolidated financial statements.  FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE.  The provisions of FIN 46 are effective immediately for all VIEs created after January 31, 2003.  For VIEs created before February 1, 2003, the provisions of FIN 46 must be adopted at the beginning of the first interim or annual reporting period beginning after June 15, 2003.   We do not have an interest in any VIEs and therefore the adoption of this pronouncement did not have an impact on our earnings or financial position.

 

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ITEM 2.        MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three months ended March 31, 2003 and 2002.  Certain prior year amounts have been reclassified to conform to the presentation used in 2003.  You should also refer to our interim consolidated financial statements and notes thereto included elsewhere in this document.  This section, as well as other sections in this Form 10-Q, contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as “may,” “intend,” “will,” “expect,” “anticipate,” “estimate,” or “continue” or the negative thereof or other variations thereon or comparable terminology.  In addition to the important factors referred to herein, numerous factors affecting the gas processing industry generally and in the specific markets for gas and NGLs in which we operate could cause actual results to differ materially from those in such forward-looking statements.

 

RESULTS OF OPERATIONS

 

Three months ended March 31, 2003 compared to the three months ended March 31, 2002

(Dollars in thousands, except per share amounts and operating data).

 

		Three Months Ended March 31,						Percent
		2003			2002			Change
Financial results:
Revenues		$	888,106		$	615,915		44
Gross profit		65,490			27,954			134
Net income		23,375			8,000			192
Earnings per share of common stock		0.65			0.18			261
Earnings per share of common stock-diluted		0.63			0.18			250
Net cash provided by operating activities		$	115,155		$	22,525		411
Operating data:
Average gas sales (MMcf/D)		1,593			2,445			(35	)
Average NGL sales (MGal/D)		1,655			1,940			(15	)
Average gas prices ($/Mcf)		$	5.44		$	2.47		(65	)
Average NGL prices ($/Gal)		$	0.62		$	0.37		(41	)

 

Net income increased $15.4 million for the three months ended March 31, 2003 compared to the same period in 2002.  The increase in net income was primarily attributable to a significant increase in gas and NGL prices in the first quarter of 2003 compared to the same period last year.  This increase in prices was supplemented by increased equity production from the Powder River Basin coal bed methane development and the Green River Basin.  Also contributing to the increase in net income was a pre-tax $7.1 million increase in operating income from our marketing operations in the three months ended March 31, 2003 compared to the same period in 2002.  Partially offsetting the increases to net income in the three months ended March 31, 2003 was a pre-tax loss of $2.8 million from the discontinuance of hedge treatment on some financial instruments and included a $6.7 million after-tax loss from the Cumulative effect of a change in accounting principle from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003.

 

Revenues from the sale of gas increased $234.2 million to $779.7 million for the three months ended March 31, 2003 compared to the same period in 2002.  This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in the three months ended March 31, 2003.  Average gas prices realized by us increased $2.97 per Mcf to $5.44 per Mcf for the quarter ended March 31, 2003 compared to the same period in 2002.  Included in the realized gas price were approximately $7.8 million of losses recognized in the three months ended March 31, 2003 related to futures positions on equity gas volumes.  We have entered into additional futures positions for approximately half of our equity gas for the remainder of 2003.  See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”.  Average gas sales volumes decreased to 1,593 MMcf per day for the quarter ended March 31, 2003 compared to the same period in 2002.  This decrease was due to a temporary reduction in third party sales volume resulting from the increase in product prices and related credit exposure.

 

Revenues from the sale of NGLs increased approximately $27.2 million to $92.0 million for the three months ended March 31, 2003 compared to the same period in 2002.  This increase is primarily due to a significant increase

 

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in product prices, which was partially offset by a reduction in sales volumes as a result of the sale of our Toca facility in September 2002.  Average NGL prices realized by us increased $0.25 per gallon to $0.62 per gallon for the three months ended March 31, 2003 compared to the same period in 2002.  Included in the realized NGL price were approximately $4.9 million of losses recognized in the three months ended March 31, 2003 related to futures positions on equity NGL volumes.  We have entered into additional futures positions for the majority of our equity NGL production for the remainder of 2003.  See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”.  Average NGL sales volumes decreased 285 MGal per day to 1,655 MGal per day for the three months ended March 31, 2003 compared to the same period in 2002.

 

Product purchases increased by $227.0 million for the quarter ended March 31, 2003 compared to the same period in 2002 as a result of the significant increase in commodity prices.  Overall, combined product purchases as a percentage of sales of all products decreased to 87% in the first quarter of 2003 from 89% in the first quarter of 2002.  The reduction in this percentage is primarily the result of an increase in product prices, an increase of sale of our equity production and increased marketing margins.

 

Marketing margins on residue gas averaged $0.10 per Mcf for the quarter ended March 31, 2003 compared to $0.02 per Mcf in the same period of 2002.  The increase in margin in the 2003 quarter primarily resulted from transactions associated with our firm transportation capacity from the Rocky Mountain region to the mid-continent.  There is no assurance, however, that these market conditions for our gas and NGL products and related margins will continue in the future, that we will be in a similar position to benefit from them or that we will continue to originate the same amount of transactions in future quarters.

 

Plant and transportation operating expense increased by $3.1 million for the three months ended March 31, 2003 compared to the same period in 2002.  This increase was primarily due to additional leased compression in the Powder River Basin coal bed development and higher utility and fuel charges at our plant facilities.  Also contributing to the increase are fees paid for gathering services on our 50%-owned Rendezvous Gas Services, L.L.C., or Rendezvous.  This investment is accounted for under the equity method and our share of revenues is reflected in Earnings from equity investments.

 

Oil and gas exploration and production expenses increased by $5.1 million for the three months ended March 31, 2003 compared to the same period in 2002.  In our operating areas, the significant increase in residue gas prices in 2003 resulted in substantially higher severance tax expenses.  This increase was partially offset by decreased lease operating expenses, or LOE, in the Powder River Basin coal bed development.   Overall, LOE averaged $0.35 per Mcf for the three months ended March 31, 2003 and LOE in the Powder River Basin coal bed development averaged $0.37 per Mcf for the three months ended March 31, 2003.  This represents decreases of $0.04 per Mcf from the same periods in 2002.  The decreases in LOE are substantially due to increased production volumes in the first quarter of 2003.

 

Selling and administrative expenses increased by $1.9 million for the three months ended March 31, 2003 as compared to the same period in 2002, due to higher health insurance costs and higher compensation expenses.

 

Depreciation, depletion and amortization increased by $197,000 for the three months ended March 31, 2003 as compared to the same period in 2002.  This increase is the result of additional capital expenditures and depletion on our oil and gas assets that was substantially offset by revisions to the operating lives and salvage values of our operating assets.  These revisions were the result of analysis performed in connection with the adoption of SFAS No. 143.

    

 In the first quarter of 2003, in order to properly align our hedged volumes of natural gas to our forecasted equity production for 2003, we discontinued hedge treatment on financial instruments for 10 MMcf per day of natural gas and 50,000 Barrels per month of ethane. As a result, a pre-tax loss of $2.8 million was reclassified into earnings in the three months ended March 31, 2003 from Accumulated other comprehensive income. 

 

Cash Flow Information

 

Cash flows from operating activities increased by $92.6 million for the three months ended March 31, 2003 compared to same period in 2002.  This increase was primarily due to an increase in net income in the 2003 period compared to the prior year, the liquidation of product inventory positions and the timing of cash receipts and payments.

 

Cash flows used in investing activities increased by $25.5 million for the three months ended March 31, 2003 compared to the same period in 2002.  This increase was primarily due to the acquisition of several gathering systems, which closed January 31, 2003.

 

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Cash flows used in financing activities increased by $57.5 million for the three months ended March 31, 2003 compared to the same period in 2002.  This increase was primarily due to an increase in net income in the 2003 period compared to the prior year and the liquidation of product inventory positions.

 

Other Information

 

Acquisition of Gathering Systems.  Effective February 1, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million.  These assets were acquired from El Paso Field Services and related entities.  These systems are comprised of a total of 550 miles of gathering lines and, in March 2003, were gathering an average of 133 MMcf per day.  Approximately 80% of the revenues to be derived from these facilities will be earned under long-term, fee-based contracts with the remaining revenue generated under keep-whole arrangements.  The three largest systems are located in the Wamsutter area of the Greater Green River Basin.  Four of these systems are located in the Wind River Basin and provide us with the opportunity to expand our gathering and processing activities into an area in which we have not previously operated.  Several of these systems are located in the Powder River Basin, do not integrate directly into our existing systems and will likely be disposed of.  These systems are classified as Assets held for sale on the Consolidated Balance Sheet at March 31, 2003.  During the first quarter of 2003, these facilities, which are included in Assets held for sale, generated net after-tax earnings of approximately $94,000, or $0.00 per share of common stock.  We believe the results from these facilities are immaterial for separate presentation as a discontinued operation.

 

Critical Accounting Policies

 

The application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules have developed.   Accounting rules generally do not involve a selection among alternatives, but involve an interpretation and implementation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business.  We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical.  Our critical accounting policies and estimates are discussed below.

 

Use of Estimates.  The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported for assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the amounts reported for revenues and expenses during the reporting period.  These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with experts and other methods considered reasonable in the particular circumstances.  However, actual results may differ significantly from the estimates used.  Any effects on our business, financial position or results of operations resulting from revisions to these estimates will be recorded in the period in which the facts that necessitate a revision become known.

 

Property and Equipment.   Our property and equipment is recorded at the lower of cost, including capitalized interest, or estimated realizable value.  Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets.

 

Depreciation on these assets is provided using the straight-line method based on the estimated useful life of each facility, which ranges from three to 35 years.  Useful lives are determined based on the shorter of our estimate of the life of the equipment or our estimate of the reserves serviced by the equipment.  Among other factors, the estimates consider our experience with similar assets and technical analysis of the reserves.  The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production.  If the actual lives of the equipment or the reserves serviced by the equipment were less than we originally estimated, we may be required to record a loss upon retirement of a specific asset.

 

In connection with the adoption of SFAS No. 143, we completed a review of our operating assets and reevaluated the operating life and salvage values of the associated equipment.  As a result of this evaluation, we extended the useful life of many of our operating assets and adjusted the estimated salvage value of our operating equipment.  These adjustments resulted in an approximate $2.5 million, or $0.04 per share of common stock - assuming dilution, decrease in depreciation, depletion and amortization in the three months ended March 31, 2003 from the expense calculated using the previous useful lives.  The adjustments to the salvage value and depreciable lives of our assets are treated as a revision of an estimate and will be accounted for on a prospective basis.

 

15

 

Oil and Gas Properties and Equipment.   We follow the successful efforts method of accounting for oil and gas exploration and production activities.  Acquisition costs, development costs and successful exploration costs are capitalized when incurred.  Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred. Upon surrender of undeveloped properties, the original cost is charged against income.  Producing properties and related equipment are depleted and depreciated by the units of production method based on estimated proved reserves.  The units of production method is sensitive to the determination of proved reserves.  We utilize technical analysis and outside expertise annually to determine the reserves associated with our oil and gas properties.   To the extent the reserves are modified based on this review, the depletion determined under the units of production method will be increased or decreased on a prospective basis.

 

Impairment of Long-Lived Assets.  If changes in the expected performance of an asset occur, or if overall economic conditions warrant, we will review our assets to determine their economic viability.  This review is completed at the plant facility, the related group of plant facilities or the oil and gas producing property level.  In order to determine whether an impairment exists, we compare the net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities.  If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset.  This analysis is sensitive to, among other things, management’s expectation of commodity prices, operating costs, drilling plans and production rates.

 

Identification of Derivatives and Mark to Market Valuations.  The determination of which contractual instruments meet the definition of a derivative under accounting rules is subject to differing interpretations as is the valuation of those derivatives.  Management uses its judgment to analyze all contracts to determine whether or not they qualify as derivatives and to determine their value.  Specific areas in which management’s judgment is required includes identifying contracts meeting the criteria for exclusions from derivatives treatment, market liquidity, and market valuation.   This analysis is sensitive to commodity prices, outside market factors and management’s intent upon entering into these contracts.

 

Significant Risks.  We are subject to a number of risks inherent in the industry in which we operate, including price volatility, counterparty credit risk, the success of our drilling programs and other gas supply.  Our financial condition and results of operations will depend significantly upon the prices we receive for gas and NGLs.  These prices are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control.  In addition, we must continually connect new wells to our gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes.  The number of new wells drilled will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within our control.

 

Recently Issued Accounting Pronouncements.  We continually monitor and revise our accounting policies as new rules are issued.  At this time, there are several new accounting pronouncements that have recently been issued, but not yet adopted, which will have an impact on our accounting when these rules become effective later in 2003.

 

Liquidity and Capital Resources

 

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities.  In the past, these sources have been sufficient to meet our needs and finance the growth of our business.  We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek additional or alternative financing sources.  Product prices, sales of inventory, the volumes of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables will all affect future net cash provided by operating activities.  Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing results, efficient operation of our facilities and our ability to obtain financing at favorable terms.

 

During the past several years, although some of our plants have experienced declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset the natural declines.  The overall level of drilling will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, availability of transportation capacity to market centers, the energy and environmental policy

 

16

 

and regulation by governmental agencies, and the availability of foreign oil and gas, none of which is within our control. There is no assurance that we will continue to be suc­cessful in replacing the dedicated reserves processed at our facilities.  Any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third-parties and us.  Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services.  A reduction in any of these activities could have a material adverse effect on our financial condition and results of operations.

 

We believe that the amounts available to be borrowed under the revolving credit facility, together with net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program.  Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital.  Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or a combination of alternatives.  While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.  We also believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet scheduled principal repayments during 2003 of $43.3 million under the Master Shelf Agreement and our preferred stock dividend requirements during the remainder of 2003 of approximately $5.4 million.

 

We have effective shelf registration statements filed with the SEC for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock.  These shelf registrations allow us to access the debt and equity markets without the requirement of further SEC review.

 

Our sources and uses of funds for the three months ended March 31, 2003 are summarized as follows (dollars in thousands):

 

Sources of funds:

 

Borrowings under the revolving credit facility		$	316,700
Borrowings under the Master Shelf Agreement		25,000
Proceeds from the dispositions of property and equipment		41
Net cash provided by operating activities		115,155
Proceeds from exercise of common stock options		1,415
Total sources of funds		$	458,311

 

Uses of funds:

 

Payments related to long-term debt (including debt issue costs)		$	391,895
Capital expenditures		57,076
Preferred dividends paid		1,811
Common dividends paid		1,653
Total uses of funds		$	452,435

 

Capital Investment Program.  Our capital expenditures during the three months ended March 31, 2003 totaled approximately $57.1 million.  Overall, capital expenditures during this quarter consisted of the following: (i) approximately $5.7 million related to gathering, processing, treating and pipeline assets, including $1.6 million for maintaining existing facilities; (ii) approximately $10.9 million related to exploration and production and lease acquisition activities; (iii) $37.1 million for the acquisition of 18 gathering systems which closed in January 2003; (iv) approximately $2.1 million for information technology and other items; and (v) approximately $1.3 million for capitalized overhead and interest.  Overall, capital expenditures in the Powder River Basin coal bed methane development and in the Green River Basin in southwest Wyoming operations represented 68% and 21%, respectively, of the total capital expenditures in the three months ended March 31, 2003.

 

We anticipate capital expenditures in 2003 of approximately $187.3 million.  The 2003 capital budget consists of the following: (i) approximately $58.2 million related to gathering, processing, treating and pipeline assets, including $11.4 million for maintaining existing facilities; (ii) approximately $79.9 million related to exploration and production and lease acquisition activities; (iii) $37.1 million for the acquisition of 18 gathering systems which closed in January 2003; (iv) approximately $4.3 million for information technology and other items and (v) $7.8 million for capitalized interest and overhead.  Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 36% and 47%, respectively, of the total 2003

 

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budget.  Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2003 will not change.  This budget may be further increased to provide for acquisitions if approved by our board of directors.

 

Contractual Commitments and Obligations

 

Contractual Cash Obligations.  A summary of our contractual cash obligations as of March 31, 2003 is as follows (dollars in thousands):

 

					Payments by Period
Type of Obligation		Total Obligation			Due in 2003			Due in 2004 - 2005			Due in 2006 - 2007			Due Thereafter
Guarantee of Fort Union Project Financing		$	6,114		$	568		$	1,669		$	1,931		$	1,946
Operating Leases		77,246			10,856			23,002			21,983			21,405
Firm Transportation Capacity and Gathering Agreements		250,512			22,838			58,311			56,885			112,478
Firm Storage Capacity Agreements		27,450			3,962			7,672			5,365			10,451
Long-term Debt		309,834			43,334			66,500			20,000			180,000
Total Contractual Cash Obligations		$	671,156		$	81,558		$	157,154		$	106,164		$	326,280

 

Guarantee of Fort Union Project Financing.  In 1998, we joined with other industry participants to form Fort Union Gas Gathering, L.L.C., or Fort Union, to construct a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River Basin in northeast Wyoming.  We own a 13% equity interest in Fort Union and are the construction manager and field operator.  Construction of the gathering header and treating system was project financed by Fort Union.  In 2001, an expansion of Fort Union was completed to increase capacity.  The expansion costs totaled approximately $22.0 million and were also project financed by Fort Union.  This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009.  All participants in Fort Union have guaranteed Fort Union’s payment of the project financing on a proportional basis, resulting in our guarantee of $6.1 million of the debt of Fort Union at March 31, 2003.  This guarantee is not reflected on our Consolidated Balance Sheet.

 

Operating Leases.  In the ordinary course of our business operations, we enter into operating leases for office space, office equipment, communication equipment and transportation equipment.  In addition, primarily to support our growing development in the Powder River coal bed development, we have entered into operating leases for compression equipment.  Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet.  As of March 31, 2003, we had leased a total of 122 compression units.  These leases have terms ranging from two to ten years with return or fair market purchase options available at various times during the lease.   If we were to exercise the early buyout options on all the leased equipment, these purchase options would require the capital expenditure of approximately $33.9 million between 2007 and 2011.  At March 31, 2003, we had four compressor units under an interim leasing agreement.  These compressors will be added to the existing lease arrangements when the equipment is installed and in service.

 

In August 2002, we entered into a lease with a seven year and nine month term for approximately 85,000 square feet of office space in Denver, Colorado.  The cumulative lease payments over the term of this agreement, which began upon occupancy, will total approximately $10.7 million.  Our corporate offices were relocated to this space in March 2003.  We also entered into a ten-year agreement effective in January 2003 for the lease of approximately 26,000 square feet of office space in Gillette, Wyoming for our Wyoming field operations.  The cumulative lease payments over the term of this agreement will total approximately $3.0 million.

 

Firm Transportation Capacity and Gathering Agreements.  Access to firm transportation is also a significant element of our business strategy.  Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur.  As of March 31, 2003, we had contracts for approximately 632 MMcf per day of firm transportation.  This amount represents our total contracted amount on many individual pipelines.  In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. In total, we have the capacity to transport 171 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent.  This utilizes a total of approximately 376 MMcf

 

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per day of firm capacity on three separate pipelines.   The total rate under these long-term contracts to transport this gas to the Mid-Continent approximates $0.35 per Mcf.  Our remaining firm capacity consists of 136 MMcf per day to markets within the Rocky Mountains and 120 MMcf per day contracted in various other markets throughout the country.  In addition, we hold 83 MMcf per day of firm gathering capacity on the Fort Union gathering line.

 

A portion of this firm transportation capacity was contracted for use in our Marketing operations.  For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 56 MMcf per day of our firm transportation capacity to the Mid-Continent, and resells the gas to various markets.  During the three months ended March 31, 2003, these types of transactions have been profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation.  Historically, to the extent these transportation contracts were acquired for our Marketing segment, they were derivative contracts as defined by SFAS No. 133 and were marked to market.  On October 1, 2002, the Federal Energy Regulatory Commission’s, or FERC, policy on capacity release expired.  After that date, companies are no longer able to re-market transportation capacity at rates which exceed the maximum allowable rate permitted by the pipelines’ tariff.  On some pipelines, this reduces our ability to liquidate our position.  Accordingly, as of October 1, 2002, the transportation contracts on these specific pipelines are no longer considered derivatives under SFAS No. 133 and were no longer marked to market.   We have elected to hedge the cash flows resulting from transactions utilizing a portion of this transportation capacity.  To the extent of these hedges the transactions are classified as cash flow hedges.  In the future, we may, from time to time, hedge additional portions of this capacity and would utilize hedge accounting for the transactions.

 

We expect that the fixed fees associated with our contracts for firm transportation capacity during the remainder of 2003 will average approximately $0.18 per Mcf per day.  The associated contract periods range from one month to fourteen years.  Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

 

Firm Storage Capacity Agreements.   We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials.  As of March 31, 2003, we had contracts in place for approximately 13.7 Bcf of storage capacity at various third-party facilities.  The fees associated with these contracts during the remainder of 2003 will average $0.29 per Mcf of annual capacity.  The associated contract periods have an average term of seventeen months.  At March 31, 2003, we held gas in our contracted storage facilities and in imbalances of approximately 4.4 Bcf at an average cost of $2.56 per Mcf compared to 9.0 Bcf at an average cost of $2.04 per Mcf at March 31, 2002.  These positions are for storage withdrawals within the next twelve months.  At the time that we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product.  We have also entered into a precedent agreement for 2.4 Bcf of annual capacity, for a term of ten years, for storage in a facility, which is not yet completed.  We anticipate the completion of the construction of this facility in 2004.  When the facility is completed, we will enter into a storage agreement.

 

From time to time, we lease NGL storage space at major trading locations in order to store products for resale during periods when prices are favorable and to facilitate the distribution of products. At March 31, 2003, we held NGLs in storage at various third-party facilities of 2,772 MGal, consisting primarily of propane and normal butane, at an average cost of $0.27 per gallon compared to 3,261 MGal at an average cost of $0.44 per gallon at March 31, 2002.

 

Long-term Debt

 

Revolving Credit Facility.  At March 31, 2003, $21.5 million was outstanding under our existing $250 million revolving credit facility.  On April 24, 2003, we amended and restated our existing revolving credit facility.   Our new facility is with a syndicate of banks, which have extended to us a $300 million four-year revolving line of credit.  A portion of the borrowings under the new $300 million credit facility was used to repay the amount outstanding under the $250 million predecessor credit agreement.

 

Loans made under the new facility are secured by a pledge of the capital stock of our significant subsidiaries, and some of our subsidiaries have also provided a guaranty of payments owed by us under the facility.  The facility also contains a provision that requires us to secure loans under the facility with 75% of our oil and gas reserves.  This provision would only be triggered in the event of an issuance of or reduction to a debt rating on the revolving credit facility of Ba3 or lower by Moody’s Investors Service, Inc., or Moody’s, or the issuance of or the reduction to a debt

 

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rating on the revolving credit facility of BB- or lower by Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc., or S&P.

 

The borrowings under the new credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio.  The base rate is the higher of the Federal Funds Rate plus 0.005% or the agent’s published prime rate.  We also pay a quarterly facility fee ranging between 0.30% and 0.50%, depending on our debt to capitalization ratio.  This fee is paid on the total commitment.  At April 30, 2003, the interest rate payable on borrowings under the new facility was approximately 3.1%.

 

Under the new credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55%; maintaining a senior debt to capitalization ratio of not more than 40%; and maintaining an EBITDA to interest and dividends on preferred stock over the last four quarters in excess of 3.25 to 1.0, increasing to 4.25 to 1.0 by March 31, 2005.

 

The new credit facility ranks equally with borrowings under our Master Shelf Agreement with The Prudential Insurance Company.

 

Master Shelf Agreement.   Effective January 13, 2003, we entered into the Third Amended and Restated Master Shelf Agreement to amend and restate our Master Shelf Agreement with The Prudential Insurance Company of America.  Amounts outstanding under the Master Shelf Agreement at March 31, 2003 are as indicated in the following table (dollars in thousands):

 

Issue Date		Amount			Interest Rate		Final Maturity		Principal Payments Due
October 27, 1992		$	8,333		7.99	%	October 27, 2003		single payment at maturity
December 27, 1993		25,000			7.23	%	December 27, 2003		single payment at maturity
October 27, 1994		25,000			9.24	%	October 27, 2004		single payment at maturity
July 28, 1995		50,000			7.61	%	July 28, 2007		$ 10,000 on each of July 28, 2003 through 2007
January 17, 2003		25,000			6.36	%	January 17, 2008		single payment at maturity
		$	133,333

 

Our borrowings under the Master Shelf Agreement are secured by a pledge of the capital stock of our significant subsidiaries, some of which have also provided a guaranty of payments owed by us under the facility.  As a result of an amendment made on April 24, 2003 to our Master Shelf Agreement, in conjunction with the amendment and restatement of our revolving credit facility, the Master Shelf now contains additional security, which may be triggered in the event of the issuance of a debt rating downgrade.  The Master Shelf requires us to secure loans under the facility with 75% of our oil and gas reserves.  This provision would only be triggered in the event of an issuance of or reduction to a debt rating on the revolving credit facility of Ba3 or lower by Moody’s or the issuance of or the reduction to a debt rating on the revolving credit facility of BB- or lower by S&P.

 

Under our Master Shelf Agreement, we are subject to a number of covenants, including: maintaining a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999; maintaining a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 40%; maintaining a quarterly test of EBITDA to interest for the last four quarters in excess of 3.25 to 1.0, increasing to 4.25 to 1.0 by March 31, 2005; and maintaining a ratio of senior debt to EBITDA of no greater than 4.0 to 1.0.

 

On January 17, 2003, we borrowed an additional $25.0 million under the Master Shelf Agreement.  The note bears interest at 6.36% and will be due in a single payment on January 17, 2008.  We have an option to prepay the amount in full, at par on January 18, 2005.  The funds we received from this borrowing were used in connection with our acquisition of 18 gathering systems in January 2003.  In the remaining three quarters of 2003, we will make required principal repayments under the Master Shelf Agreement totaling $43.3 million.  We intend to fund these repayments with funds available under the revolving credit facility.

 

Senior Subordinated Notes.  In 1999, we sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradable notes under the same terms and conditions.  The Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%.  These notes contain covenants, which include limitations on debt incurrence, restricted payments, liens and sales of assets.  The Subordinated Notes are unsecured and are guaranteed

 

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on a subordinated basis by our material subsidiaries.  We incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes.

 

Covenant Compliance.  We were in compliance with all covenants in our debt agreements at March 31, 2003.

 

 

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Upstream Operations

 

A vital aspect of our long-term business plan is to double proven reserves and equity production of natural gas from the level at December 31, 2001 over a three to five year period.  In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River coal bed methane development and the Green River Basin.  Each of our existing upstream projects are fully integrated with our midstream operations. In other words, we provide the gathering, compression, processing, marketing or transportation services for both our own production and for third-party operators.

 

Powder River Basin Coal Bed Methane.  We continue to develop our Powder River Basin coal bed methane reserves and expand the associated gathering system in northeast Wyoming.  The Powder River Basin coal bed methane area is currently one of the largest on-shore plays for the development of natural gas in the United States.  Within this area, together with our co-developer, in the first three months of 2003, we were the largest producer of natural gas.  In addition, Western is the largest gatherer of natural gas and, through our MIGC pipeline, transports a significant volume of gas out of this basin.

 

At March 31, 2003, we held the drilling rights on approximately 528,000 net acres in this basin, and as of December 31, 2002, we had established proven developed and undeveloped reserves totaling 414 Bcfe on a portion of this acreage, 52% of which are proven and developed.   The drilling operations in the Powder River Basin through March 31, 2003 have primarily focused on developing reserves in the Wyodak coal, which is located on the east side of the coal bed development.  We participated in the drilling of 101 gross wells in the first three months of 2003.  We plan to participate in a total of 845 gross wells in 2003, including 441 scheduled to be drilled in the Wyodak coal and 404 scheduled to be drilled in the Big George coal. The average drilling and completion cost for our coal bed methane gas wells is approximately $90,000 to $120,000 per well with average reserves per successful well of approximately 275 MMcf.  The majority of future development will be concentrated on developing the Big George and other coal seams.  Much of the Big George coal seam is deeper and thicker than the Wyodak coal.  We expect that as wells are drilled and developed in the Big George coal, the gas reserves and production per well and the average drilling and completion cost per well will increase.

 

Our share of production from wells in which we own an interest averaged approximately 106 MMcfe per day in the first quarter of 2002 and increased to an average of approximately 124 MMcfe per day in the first quarter of 2003.  We currently anticipate reaching an average production rate of 132 net MMcfe per day from this area in December 2003, assuming that the issuance of permits on federal leases as a result of the EIS, as described below, are not unreasonably delayed.

 

Industry-wide, production from the Big George coal increased by 293% in 2002 and in February 2003, production rates totaled approximately 82 MMcf per day from eight separate pilots.  We are currently evaluating 11 pilot areas and one development area in the Big George.  Through March 31, 2003, we have drilled approximately 440 gross wells in the Big George coal area.  We have marketable production quantities in the All Night Creek, Pleasantville and Kingsbury areas.  At April 30, 2003, these areas were producing a combined 30.0 gross MMcf per day.  At December 31, 2002, we had proven reserves of 49 Bcfe in the Big George coal, primarily associated with the All Night Creek development area.

 

On April 30, 2003, the Bureau of Land Management, or BLM, issued the final Record of Decision, or ROD, in relation to its Environmental Impact Statement, or EIS, regarding future CBM drilling in the Powder River Basin.  We are currently in the process of reviewing the ROD to determine its impact on our operations in this area.  More planning will be required for permitting related to certain plant and animal species, cultural surveys and noxious weed mitigation.  We intend to commence filing permit applications for approval by the BLM under the terms of the new EIS, but are unable to predict the rate at which permits will be granted.  This timing may also be affected by several lawsuits, which were filed on May 1, 2003 in the U.S. District Court in Billings, Montana challenging the BLM’s decision.  While we believe that these lawsuits are unlikely to be successful, we are unable to predict the outcome of the litigation or the impact, if any, on the timing of our development.

 

Additionally, the Wyoming Department of Environmental Quality, or DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The majority of wells on our acreage producing from the Wyodak formation drain into these areas.  The Wyoming and Montana DEQ offices have reached agreement on procedures for discharging and

 

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monitoring water into the Powder River and other drainage areas, in which most of our undeveloped prospects are located.  Additional procedures for obtaining permits under this agreement are addressed in the EIS referred to above.

 

On April 26, 2002, the Interior Board of Land Appeals, or IBLA, ruled that the BLM did not comply with the National Environmental Policy Act, or NEPA, prior to issuing three federal oil and gas leases held by an unaffiliated third-party in the Powder River Basin.  There has not been a final decision regarding the validity of the three leases.  The IBLA has remanded the case to the Wyoming BLM State Director without specifying a remedy.  The State Director could, among other things, require additional NEPA analysis to be done on these three leases. The unaffiliated leaseholder has filed for judicial review in federal district court in Wyoming.  We do not have any interests in these leases nor have we received notice of any challenge to leases that we hold.  We are continuing to monitor the development of the issue. The recently concluded EIS includes a NEPA analysis covering coal bed methane development, which may resolve the defects identified by the IBLA. 

 

Our 2003 capital budget in the Powder River Basin coal bed development includes approximately $55.2 million for drilling costs, production equipment and lease acquisitions, of which approximately $9.2 million was spent in the first quarter of 2003.  Depending upon future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin.  In addition, due to regulatory uncertainties, which are beyond our control, we can make no assurance that we will incur this level of capital expenditure.  Our co-developer in this area is also required to make similar capital commitments to continue the pace of the development as planned.  During 2002, our co-developer in this area publicly disclosed that it had financial difficulties.  We are currently unable to predict the impact, if any, of our co-developer’s financial situation on the future pace of development in the Powder River Basin.  Several disputes have arisen between our co-developer and us.  These disputes are more fully described in Part II — Other Information - Item 1. Legal Proceedings.

 

Green River Basin.  Our upstream assets in the Green River Basin of southwest Wyoming are located in the Jonah Field and Pinedale Anticline areas.  As of March 31, 2003, we owned approximately 194,000 gross oil and gas leasehold acres, or approximately 33,000 net acres, in these areas.  During the first quarter of 2003, we participated five gross wells, or one net well, in these areas, at a cost of $1.6 million and experienced a success rate of 100%.  Our capital budget for 2003 in the Jonah Field and Pinedale Anticline areas provides for expenditures of approximately $17.9 million for drilling costs and production equipment.  Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.  During the remainder of 2003, we expect to participate in the drilling of 60 gross wells, or approximately seven net wells on the Pinedale Anticline.  The expected drilling and completion costs per gross well range from approximately $3.5 million to $5.0 million, depending on location and depth.  Average well depths in this area range from approximately 13,000 feet to 14,200 feet depending on the objective formation and average gross reserves per successful well approximate 6 to 8 Bcfe.  During March 2003, we produced an average of 19.5 MMcfe per day, net, from these areas.  We had established proven developed and undeveloped reserves totaling 161 Bcfe at December 31, 2002.  There can be no assurance, however, as to the ultimate recovery of these reserves.

 

Production Information.  The following table provides a summary of our net quarterly production volumes:

 

		Three Months Ended March 31,
		2003				2002
State/Basin		Gas (MMcf)		Oil (MBbl)		Gas (MMcf)		Oil (MBbl)
Colorado - Sand Wash Basin		292		1		228		—
Texas (1)		8		2		14		3
Wyoming:
Powder River Basin		11,196		—		9,579		—
Green River Basin		1,618		11		1,050		7
Total		13,114		14		10,871		10

 

(1)                    Represents a small non-operating working interest in several wells in the Austin Chalk area.

 

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Midstream Operations

 

Our midstream operations consist of our gathering, processing, treating, marketing and transportation operations.  An important element of our long-term business plan is to meet or exceed throughput projections in these areas and to optimize their profitability.  To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections and through the expansion or acquisition of gathering or processing systems.  We also seek to increase the efficiency of our operations by modernization of equipment and the consolidation of existing facilities.

 

Effective February 1, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million.  These assets were acquired from EPFS, and related entities.  These systems are comprised of a total of 550 miles of gathering lines and, in March 2003, were gathering a total of 133 MMcf per day.  The three largest systems are located in the Wamsutter area of the Greater Green River Basin.   Four of these systems are located in the Wind River Basin and provide us with the opportunity to expand our gathering and processing activities into an area in which we have not previously operated.  Several of the systems are located in the Powder River Basin, do not integrate directly into our existing systems and will likely be disposed of.

 

Gas Gathering, Processing and Treating.

 

At March 31, 2003, we operated a total of 21 significant gathering, processing and treating facilities, or plant operations, with approximately 9,797 miles of gathering lines.  These facilities are located in five states and have a combined throughput capacity of 2.9 billion cubic feet, Bcf, per day of natural gas.  Our operations are located in some of the most actively drilled oil and gas producing basins in the United States.  Five of our processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane and natural gasoline to obtain a higher value for the NGLs, and three of our plants are capable of processing and treating natural gas containing hydrogen sulfide or other impurities that require removal prior to delivery to market pipelines.   In the first quarter of 2003, we gathered an average of 1.3 Bcf per day of natural gas, produced natural gas for delivery to markets of 874 MMcf per day and produced 1.8 MMgal per day of NGLs.  In addition to our integrated upstream and midstream operations in the Powder River and Green River Basins in Wyoming, our core assets include our plant operations located in west Texas and Oklahoma.  We believe that our core assets have stable production rates, provide a significant operating cash flow and continue to provide us with strategic growth opportunities.

 

Powder River Basin. Our midstream operations in the Powder River Basin are fully integrated with our upstream operations.  In other words, we provide the gathering, compression and processing services for both our own production and for third-party operators.  As of March 31, 2003, our assets in the Powder River Basin in northeast Wyoming were primarily comprised of our coal bed methane gathering system with a capacity of 525 MMcf per day, our 13% equity interest in Fort Union and several small gas processing facilities.

 

We are the construction manager and field operator of the Fort Union gathering system and header.  The Fort Union system delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States.  The gathering pipeline has a capacity of 635 MMcf per day.  We have entered into long-term, firm gathering agreements with Fort Union for 83 MMcf per day of capacity at $0.14 per Mcf.

 

Our capital budget in the Powder River Basin for midstream activities provides for expenditures of approximately $14.7 million during 2003, of which approximately $3.3 million was spent in the first quarter.  We have also entered into a number of operating leases for compression equipment primarily in the coal bed gathering area.  Depending upon our future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin.  Due to drilling, regulatory, commodity pricing and other uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

 

Green River Basin.  Our midstream operations in the Green River Basin of southwest Wyoming are also fully integrated with our upstream operations in this area.  Our midstream assets in this basin are comprised of the Granger and Lincoln Road facilities, or collectively the Granger complex, our 50% equity interest in Rendezvous and our Red Desert facility.  These facilities have a combined gathering capacity of 465 MMcf per day and a combined processing capacity of 327 MMcf per day.  In the three months ended March 31, 2003, these facilities averaged throughput of 393 MMcf per day.

 

Our 2003 capital budget for midstream activities in this basin provides for expenditures of approximately $63.9 million

 

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during 2003 of which $37.3 million was spent in the first quarter.  This capital budget includes approximately $21.2 million for gathering lines and installation of compression to expand the capacity of our Granger Complex, $5.6 million for additional contributions to Rendezvous for the expansion of its system and $37.1 million for the acquisition of 18 additional gathering systems in January 2003.   Due to drilling, commodity pricing and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

 

In 2001, we, together with an unrelated third-party, formed Rendezvous.  Rendezvous gathers gas along the Pinedale Anticline for blending or processing at either our Granger Complex or at the third-party owned and operated Blacks Fork processing facility.   Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. Rendezvous has a capacity of 275 MMcf per day and at March 31, 2003 was gathering 234 MMcf per day.   An expansion of the system is scheduled to be completed in the fourth quarter of 2003.  The expansion would extend the system approximately 24 miles further into the Pinedale Anticline at an estimated cost of $11.1 million gross, of which our share is approximately $5.6 million.

 

West Texas.  Our primary assets in west Texas are the Midkiff/Benedum complex and the Gomez treating facility.  These facilities process gas produced by third-parties in the Permian Basin, have a combined operational capacity of 565 MMcf per day and processed an average of 280 MMcf per day in the first quarter of 2003.  Also in this quarter, these facilities produced an average of 205 MMcf per day of natural gas for delivery to sales markets and produced an average of 772 MGal per day of NGLs.  Our capital budget in this area provides for expenditures of approximately $6.0 million during 2003, of which $500,000 was spent in the first quarter.

 

Oklahoma.  Our primary assets in Oklahoma are the Chaney Dell and Westana systems.  These facilities process gas produced by third-parties in the Anadarko Basin and have a combined operational capacity of 175 MMcf per day.  In the three months ended March 31, 2003, these facilities processed an average of 152 MMcf per day, produced an average of 135 MMcf per day of natural gas for delivery to sales markets and produced 301 MGal per day of NGLs.  Our capital budget in this area provides for expenditures of approximately $9.0 million during 2003, of which approximately $1.4 million has been spent in the first quarter.

 

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Principal Facilities.  The following tables provide information concerning our principal gathering, processing and treating facilities and transportation assets at March 31, 2003.  We also own and operate several smaller treating, processing and transportation facilities located in the same areas as our other facilities.

 

								Average for the Three Months Ended March 31, 2003
Facilities (1)		Year Placed In Service		Gas Gathering System Miles (2)		Gas Throughput Capacity (MMcf/D (3)		Gas Throughput (MMcf/D (4)		Gas Production (MMcf/D (5)		NGL Production (MGal/D (5)
Texas
Gomez Treating (6)		1971		386		280		84		76		—
Midkiff/Benedum		1949		2,222		165		131		89		771
Mitchell Puckett Gathering (6)		1972		93		120		64		40		1
Wyoming
Coal Bed Methane Gathering		1990		1,298		525		414		220		—
Desert Springs Gathering (13)		1979		65		10		4		4		2
Fort Union Gas Gathering		1999		106		635		474		474		—
Granger (7)(8)(9)		1987		532		235		237		153		407
Hilight Complex (7)		1969		626		124		14		9		48
Kitty/Amos Draw (7)		1969		314		17		6		4		25
Lincoln Road (9)		1988		149		50		32		—		—
Newcastle (7)		1981		146		5		3		2		19
Red Desert (7)		1979		111		42		21		10		12
Rendezvous Gas Services		2001		—		275		224		224		—
Reno Junction (8)		1991		—		—		—		—		100
Table Rock Gathering (13)		1979		101		20		11		11		—
Wamsutter Gathering (13)		1979		185		50		26		26		10
Wind River Gathering (13)		1979		109		80		36		36		—
Oklahoma
Chaney Dell		1966		2,093		130		87		84		296
Westana		1981		1,017		45		63		51		5
New Mexico
San Juan River (6)		1955		140		60		30		24		49
Utah
Four Corners Gathering		1988		104		15		3		2		16
Total				9,797		2,883		1,964		1,539		1,761

 

						Average for the Three Months Ended March 31, 2003
Transportation Facilities (1)		Year Placed In Service		Transportation Miles(2)		Pipeline Capacity (MMcf/D)(2)		Gas Throughput (MMcf/D)(4)
MIGC (10)(12)		1970		245		130		179
MGTC (11)		1963		252		18		14
Total				497		148		193

 

Footnotes on following page.

 

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(1)                   Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union gathering system (13%) and Rendezvous Gas Services (50%).  We operate all facilities, and all data include our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility.  Unless otherwise indicated, all facilities shown in the table are gathering, processing or treating facilities.

(2)                   Gas gathering system miles, transportation miles and pipeline capacity are as of March 31, 2003.

(3)                   Gas throughput capacity is as of March 31, 2003 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(4)                   Aggregate wellhead natural gas volumes collected by a gathering system or volumes transported by a pipeline.

(5)                   Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third-parties.

(6)                   Sour gas facility (capable of processing or treating gas containing hydrogen sulfide and/or carbon dioxide).

(7)                   Processing facility that includes fractionation (capable of fractionating raw NGLs into end-use products).

(8)                   NGL production includes conversion of third-party feedstock to iso-butane.

(9)                   Lincoln Road is operated on an intermittent basis to process excess gas from the Granger system.

(10)             MIGC is an interstate pipeline located in Wyoming and is regulated by the Federal Energy Regulatory Commission.

(11)             MGTC is a public utility located in Wyoming and is regulated by the Wyoming Public Service Commission.

(12)             Pipeline capacity represents certificated capacity at the Powder River junction only and does not include interruptible capacity or capacity at other delivery points.

(13)             These facilities were acquired on January 31, 2003 with an effective date of February 1, 2003.

 

Transportation.

 

We own and operate MIGC, Inc. an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, Inc. an intrastate pipeline located in northeast Wyoming.  MIGC charges a FERC approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC.  During the three months ended March 31, 2003, MIGC transported an average of 178 MMcf per day.  It is anticipated that MIGC will continue to operate around that level through the remainder of 2003.  MIGC earns fees on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline.  Contracts for firm capacity on MIGC range in duration from one month to six years and the fees charged average $0.33 per Mcf.

 

The FERC has implemented changes over the past several years to restrict transactions between regulated pipelines and affiliated companies.  In addition, the FERC has proposed to limit the use of affiliates’ employees in the operation of regulated entities.  In August 2002, the FERC issued a Notice of Proposed Rule Making that, if enacted, would require MIGC to establish its own cash management function, including its own revolving credit facility, and would limit the ability of MIGC to transfer funds to us.  Further, this proposed rule may require us to modify our existing subsidiary guarantees under our debt agreements.  We can make no assurances as to the ultimate regulations passed by the FERC or the effects such regulations may have on the operating costs of MIGC or our financial position.

 

MGTC provides transportation and gas sales to the Wyoming cities of Gillette, Moorcroft and Wright at rates that are subject to the approval of the Wyoming Public Service Commission.  During the three months ended March 31, 2003, MGTC transported an average of 14 MMcf per day and sold an average of 1 MMcf per day.

 

Marketing.

 

Gas.   We market gas produced at our wells and our plants and purchased from third-parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada.  In addition to our offices in Denver, we have marketing offices in Houston, Texas and Calgary, Alberta.  Historically, our gas marketing was an outgrowth of our gas processing activities and was directed toward selling gas processed at our plants to ensure their efficient operation. As the natural gas industry became deregulated and offered more opportunity, we increased our third-party gas marketing.  Third-party sales, firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.  For the three months ended March 31, 2003, our total gas sales volumes averaged 1.6 Bcf per day, of which 476 MMcf per day was produced at our plants or from our producing properties.

 

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One of the primary goals of our gas marketing operations continues to be the preservation and enhancement of the value received for our equity volumes of natural gas.  This goal is achieved through the use of hedges on the production of our equity natural gas and through the use of firm transportation capacity.  For example, during the three months ending March 31, 2003, as a result of limited pipeline capacity from the Rocky Mountain region to market centers in the mid-continent and west coast areas, natural gas in this region has sold at a substantial discount to these other market areas.  We had commodity price hedges and firm transportation capacity to the mid-continent markets on approximately 100% of our equity production in the Rocky Mountain area for this time period.  This allowed us to realize an approximate $0.42 per Mcf improvement in price for natural gas per MMbtu relative to the price that would have been received if these hedges and capacity rights had not existed.  We have similar hedges and transportation positions for approximately 99% of the estimated equity production of natural gas in the Rocky Mountain region for the remainder of 2003.

 

We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. As of March 31, 2003, the average duration of our sales contracts was 17 months.  The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price.  Revenues for sales of product are recognized at the time the gas is delivered to the customer and are sensitive to changes in the market prices of the underlying commodities.  We record revenue on our physical gas marketing activities on a gross basis versus sales net of purchases basis.  We believe that this presentation is required because we obtain title to all the gas that we buy including third-party purchases, bear the risk of loss and credit exposure on these transactions and it is our intention upon entering these contracts to take physical delivery of the natural gas.   Gains and losses on any accompanying financial transactions are recorded net.  Additionally, for our marketing activities, we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination.  To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.  In general, we do not expect to increase our third-party sales volumes in 2003 significantly from levels achieved over the last several years, and in fact, due to price volatility and credit concerns in the energy industry, our overall sales volumes may decrease.

 

NGLs.   We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third-parties, in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States.  A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States.  Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production.  For the three months ended March 31, 2003, NGL sales averaged 1,655 MGal per day, of which 1,394 MGal per day was produced at our plants.

 

Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets.  As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics products.  Over the last several years, the petrochemical industry has increased its use of NGLs as a major feedstock and is projected to continue to increase such usage.  Further, consumers use propane for home heating, transportation and agricultural applications.  Price, seasonality and the economy primarily affect the demand for NGLs.

 

Our NGL sales to third-parties decreased by approximately 285 MGal per day in the three months ended March 31, 2003 compared to the same period in 2002 primarily as a result of the sale of our Toca facility in September 2002.  As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counterparties.

 

We sell NGLs under agreements with varying terms and conditions in order to match seasonal and other changes in demand. At March 31, 2003, the terms of our sales contracts range from one month to five years.  The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price.  Revenues for sales of NGLs are recognized at the time the NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities.  We record revenue on our physical NGL marketing activities on a gross sales versus sales net of purchases basis.  We believe that this presentation is required because we obtain title to all the NGLs that we buy including third-party purchases, bear the risk of loss and credit exposure on these transactions and it is our intention upon entering these contracts to take physical delivery of the product.  Gains and losses on any accompanying financial transactions are recorded net.  Additionally, for our marketing activities we utilize mark-to-market accounting.  Under mark-to-market accounting, the expected margin to be

 

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realized over the term of the transaction is recorded in the month of origination.  To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

 

Recent Changes to Environmental Regulations.  Federal regulations regarding spill prevention and containment have recently been modified to establish a lower threshold of storage capacity of petroleum and petroleum by-products at a site for which a spill prevention plan is required.  We are evaluating all of our assets for compliance with this regulation and estimate that approximately 100 existing sites will need to be modified to meet the new requirements.  We currently estimate our costs for compliance to be approximately $2.0 million.  The new spill prevention plans must be in place for covered assets by August 2004.  All modifications called for in those plans must be in place by February 2005.

 

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ITEM 3.        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Our commodity price risk management program has two primary objectives.  The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow, net income and earnings per common share in relation to those anticipated by our operating budget.  The second goal is to manage price risk related to our gas, crude oil and NGL marketing activities to protect profit margins.  This risk relates to fixed price purchase and sale commitments, the value of storage inventories and exposure to physical market price volatility.

 

We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these goals.  These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market.

 

We use futures, swaps and options to reduce price risk and basis risk.  Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging.  Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged.  Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.

 

We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and through OTC swaps and options with various counterparties, consisting primarily of financial institutions and other natural gas companies.  We conduct our standard credit review of OTC counterparties and have agreements with many of these parties that contain collateral requirements.  We generally use standardized swap agreements that allow for offset of positive and negative exposures.  OTC exposure is marked-to-market daily for the credit review process.  Our OTC credit risk exposure is partially limited by our ability to require a margin deposit from our major counterparties based upon the mark-to-market value of their net exposure.  We are subject to margin deposit requirements under these same agreements.  In addition, we are subject to similar margin deposit requirements for our NYMEX counterparties related to our net exposures. In 2003, the prices for natural gas, crude oil and NGL products have increased significantly.  For example, the NYMEX contract for March 2003 delivery of natural gas closed at $9.13 per MMbtu as compared to $2.39 per MMbtu for the NYMEX contract for March 2002.  Primarily as a result of our equity hedge positions for natural gas and liquid products, we have posted margin totaling $12.8 million with various counterparties at April 30, 2003.

 

We continually monitor and review the credit exposure to our marketing counterparties.  As prices in 2003 have increased over the previous year, we have become increasingly concerned with our counterparty credit exposure.  As a result, we have reduced our sales of third-party natural gas volumes to reduce our credit exposure.  Additionally, beginning in 2001, we became increasingly concerned with our credit exposure to our customers, primarily a category of our customers generally known as “energy merchants.”  Energy merchants create liquidity in the marketplace for natural gas transactions and have historically been some of our largest suppliers and customers.  In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and reduced the amount of credit which we make available to various customers.  Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of these customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

 

We have identified one Master Swap Agreement containing ratings triggers.  Under this agreement, either party may be required to post additional collateral in the event of a decrease in their current rating by Standard & Poor’s or Moody’s Investors Service.  Based on our outstanding positions under this agreement and our counterparty’s credit rating at April 30, 2003, we were holding approximately $3.4 million of collateral.

 

The use of financial instruments may expose us to the risk of financial loss in some circumstances, including instances when (i) our equity volumes are less than expected, (ii) our customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) our OTC counterparties fail to perform.  To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market.  However, we are similarly insulated against decreases in these prices.

 

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Risk Policy and Control.  We control the extent of risk management and marketing activities through policies and procedures that involve the senior level of management.  On a daily basis, our marketing activities are audited and monitored by our independent risk oversight department, or IRO.  This department reports to the Chief Financial Officer, thereby providing a separation of duties from the marketing department.  Additionally, the IRO reports monthly to the Risk Management Committee, or RMC.  This committee is comprised of corporate managers and officers and is responsible for developing the policies and guidelines that control the management and measurement of risk. The RMC is also responsible for setting risk limits, including value-at-risk and dollar stop loss limits.  Our board of directors approves the risk limit parameters and risk management policy.

 

Hedge Positions.  As of April 30, 2003, we have hedged approximately 51% of our projected equity natural gas volumes and approximately 77% of our estimated equity production of crude oil, condensate, and NGLs.  These contracts are designated and accounted for as cash flow hedges.  As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders’ equity.  Any gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur.  Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Non-cash change in the fair value of derivatives.  This ineffectiveness is primarily due to the use of crude oil swaps in hedging the variability in the sales price of butanes.  During the three months ended March 31, 2003, we recognized a total of $53,000 of loss from the ineffective portions of our hedges.  Overall, our hedges are expected to continue to be “highly effective” under SFAS 133 in the future. 

 

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of the forecasted transaction being hedged so that our exposure to the risk of commodity price changes is reduced.  To meet this requirement, we hedge both the price of the commodity and the basis between that derivative’s contract delivery location and the cash market location used for the actual sale of the product.  This structure attains a high level of effectiveness, insuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the cash price of the hedged commodity.  We utilize crude oil as a surrogate hedge for butanes.  This typically results in an effective hedge as crude oil and butane prices historically have moved in tandem.

 

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Outstanding Equity Hedge Positions and the Associated Basis for 2003.  The following table details our hedge positions as of April 30, 2003.  In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price.  The prices for NGLs do not include the cost of the hedges of approximately $698,000.

 

Product		Quantity and NYMEX or Settlement Price		Hedge of Basis Differential
Natural gas		50,000 MMbtu per day with an average price of $3.94 per MMbtu.		Mid-Continent - 22,000 MMbtu per day with an average basis price of ($0.16) per MMbtu.
		20,000 MMbtu per day with a minimum price of $3.50 per MMbtu and an average maximum price of $4.43/MMbtu.		Permian - 5,000 MMbtu per day with an average basis price of ($0.13) per MMbtu.
				Rocky Mountain - 43,000 MMbtu per day with an average basis price of ($0.79) per MMbtu.
Crude Oil		55,000 Barrels of crude oil per month with an average price of $24.97 per barrel.		Not Applicable
Butanes		50,000 Barrels of crude oil per month.  Floor at $24.00 per barrel.  (Crude oil is used as a surrogate for butanes).		Not Applicable
Propane		100,000 Barrels per month.  Average minimum and maximum price of $0.37 per gallon and $0.50 per gallon, respectively.		Not Applicable
Ethane		81,000 Barrels per month.  Average minimum and maximum price of $0.25 per gallon and $0.37 per gallon, respectively.		Not Applicable

 

Account balances related to equity and transportation hedging transactions at March 31, 2003 were $8.9 million in Current Assets from price risk management activities, $24.9 million in Current Liabilities from price risk management activities, ($5.9) million in Deferred income taxes payable, net, and a $10.3 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Shareholders’ Equity.  Based on commodity prices as of March 31, 2003, the after-tax loss of $10.3 million will be re-classified from Accumulated other comprehensive income to Total Revenues during the next nine months.

 

Summary of Derivative Positions.  A summary of the change in our derivative position from December 31, 2002 to March 31, 2003 is as follows (dollars in thousands):

 

Fair value of contracts outstanding at December 31, 2002		$	63
Decrease in value due to change in price		(25,188		)
Increase in value due to new contracts entered into during the period		11,567
Gains realized during the period from existing and new contracts		274
Changes in fair value attributable to changes in valuation techniques		—
Fair value of contracts outstanding at March 31, 2003		$	(13,284	)

 

A summary of our outstanding derivative positions at March 31, 2003 is as follows (dollars in thousands):

 

		Fair Value of Contracts at March 31, 2003
Source of Fair Value		Total Fair Value			Maturing In 2003			Maturing In 2004-2005			Maturing In 2006-2007			Maturing Thereafter
Exchange published prices		$	(26,621	)	$	(24,580	)	$	(2,041	)	—			—
Other actively quoted prices (1)		19,685			20,262			(569		)	$	(8	)	—
Other valuation methods (2)		(6,348		)	(6,349		)	1			—			—
Total fair value		$	(13,284	)	$	(10,667	)	$	(2,609	)	$	(8	)	—

 

(1)               Other actively quoted prices are derived from broker quotations, trade publications, and industry indices.

(2)                    Other valuation methods are the Black-Scholes option-pricing model utilizing prices and volatility obtained from broker quotations, trade publications, and industry indices.

 

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Foreign Currency Derivative Market Risk.  As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars.  We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage, and transportation obligations.  This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation.  As of March 31, 2003, the net notional value of such contracts was approximately $1.1 million in Canadian dollars, which approximates fair market value.

 

ITEM 4.        CONTROLS AND PROCEDURES

 

Evaluation of disclosure controls and procedures.

 

Under the direction of the Chief Executive Officer and President and the Executive Vice President and Chief Financial Officer, we have reviewed and evaluated our disclosure controls and procedures and believe, as of the date of management’s evaluation, that our disclosure controls and procedures are reasonably designed to be effective for the purposes for which they are intended.  The review and evaluation was performed within 90 days prior to the filing of this report.

 

Changes in internal controls.

 

There have not been any significant changes in our internal controls or any other factors that could significantly affect these controls subsequent to the date of management’s evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

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PART II - OTHER INFORMATION

 

ITEM 1.        LEGAL PROCEEDINGS

 

Western Gas Resources, Inc. and Lance Oil & Gas Company, Inc. v. Williams Production RMT Company., (Defendant), Civil Action No. CO2-10-394, District Court, County of Sheridan, Wyoming.   On October 23, 2002, we filed a complaint for declaratory relief and damages related to a dispute arising under a development agreement and other agreements between the parties. The dispute centers on Defendant’s acquisition of Barrett by merger consummated on August 2, 2001.  We believe we were entitled to a preferential right to purchase certain properties of Barrett located in the Powder River Basin of Wyoming and that our consent was required prior to Barrett’s assignment of its interests in the Agreements to the Defendant.  We also believe that Barrett (now Defendant) should no longer be the operator of these properties as a consequence of the merger transaction.

 

In the fourth quarter of 2002, the Defendant asserted breach of contract claims against us.  The Defendant also claimed damages under its gathering agreement with us.  We believe that the Defendant’s assertions have no merit.  We have also asserted breach of contract claims against the Defendant for its operating practices.  The parties began mediation of these issues in the first quarter of 2003.  At this time, we are unable to predict the outcome of this litigation or the claims scheduled for mediation.

 

United States of America and ex rel. Jack J. Grynberg v. Western Gas Resources, Inc., et al., United States District Court, District of Colorado, Civil Action No. 97-D-1427.  We are a defendant in litigation, along with 300 natural gas companies in 74 separate actions, filed by Mr. Grynberg on behalf of the federal government.  The allegations made by Mr. Grynberg are that established gas measurement and royalty calculation practices improperly deprived the federal government of appropriate natural gas royalties and violate the False Claims Act.  The cases have been consolidated to the United States District Court for the District of Wyoming.  Discovery is in the initial stages to determine if this matter qualifies as a qui tam (or class) action.  On October 9, 2002, the court dismissed Mr. Grynberg’s valuation claims, and he has appealed this decision.  We believe that Mr. Grynberg’s claims are baseless and without merit and intend to vigorously contest the allegations in this case.  At this time, we are unable to predict the outcome of this matter.  There have been no material developments in this lawsuit since the matters were reported in our Annual Report on Form 10-K for the year ended December 31, 2002.

 

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30.  We are a defendant in litigation, along with numerous other natural gas companies, in which Mr. Price is claiming an under measurement of gas and Btu volumes throughout the country.  We along with other natural gas companies filed a motion to dismiss for failure to state a claim.  The court denied these motions to dismiss.   In the first quarter of 2003, the court denied plaintiff’s motion for certification as a class.  We believe that Mr. Price’s claims are baseless and without merit and intends to vigorously contest the allegations in this case.  At this time, we are unable to predict the outcome of this matter.

 

Wyoming Department of Revenue.  The Wyoming Department of Revenue has conducted an audit of Lance Oil & Gas Company, Inc. for the period from January 1, 1998 through December 31, 1999.  On March 24, 2003, the Department of Revenue notified us that it had assessed additional severance taxes and increased taxable value for ad valorem tax purposes.  The additional severance and ad valorem taxes claimed by the Department of Revenue amount to $196,000 and $351,000, respectively, together with statutory interest.  We believe that the Wyoming

 

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Department of Revenue claims are without merit and intend to vigorously contest their assessments.  On April 23, 2003, we filed a Notice of Appeal with the Wyoming State Board of Equalization.

 

Retirement Plan.  Our retirement plan for our employees includes a fund, which allows them to invest in our common stock.  The fund manager, Fidelity Investments, purchases this stock in open market transactions.  Under SEC rules, the stock purchased by the plan participants during a portion of 2001 and 2002 may be required to be registered by us.  To resolve this issue, we intend to file a registration statement on Form S-3 with the SEC and offer to rescind or pay damages related to certain employee-initiated transactions during that period.  Any stock acquired by us through this rescission offer will be treated as treasury stock.  While we are unable to estimate the cost or results of the rescission offer, we do not expect the costs to have a material adverse effect on our financial position or results of operations.

 

Other Litigation.   We are involved in various other litigation and administrative proceedings arising in the normal course of business.  In the opinion of our management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on our financial position or results of operations.

 

ITEM 6.        EXHIBITS AND REPORTS ON FORM 8-K

 

(a)                   Exhibits:

 

Exhibit Number		Description
3.1		Certificate of Incorporation of Western Gas Resources, Inc.  (Filed as exhibit 3.1 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2		Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc.  (Filed as exhibit 3.2 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3		Certificate of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock of the Company.  (Filed as exhibit 3.5 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-43077 and incorporated herein by reference).
3.5		Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on April 7, 2003.
10.1		Tenth Amendment, dated January 3, 2003, to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and Bank of America, N.A., as agent, and the Lenders (previously filed as Exhibit 10.28 to our 2002 Annual Report on Form 10-K and incorporated herein by reference).
10.2		Credit Agreement, dated as of April 24, 2003, among Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Bank One, NA and Fleet National Bank, as Co-Syndication Agents, The Royal Bank of Scotland plc and Wachovia Bank, National Association, as Co-Documentation Agents, and the Other Lenders Party Thereto.
10.3		Intercreditor Agreement, dated as of April 24, 2003, by and among the banks (as defined therein), Bank of America, N.A., as Administrative Agent for the banks and The Prudential Insurance Company of America, Pruco Life Insurance Company, ING Life Insurance & Annuity Company and Prudential Investment Management, Inc., consented to agreed by Western Gas Resources, Inc. and its subsidiaries listed therein.
10.4		Third Amended and Restated Master Shelf Agreement, dated as of December 19, 1991 (effective as of January 13, 2003), by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management Company, Inc. and ING Life Insurance & Annuity Company (filed as Exhibit 10.29 to our 2002 Annual Report on Form 10-K and incorporated herein by reference).
10.5		Letter Amendment No. 1 to Third Amended and Restated Master Shelf Agreement, dated as of April 24, 2003, by and among Western Gas Resources, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc. and ING Life Insurance & Annuity Company.
99		Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.

 

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(b)		Reports on Form 8-K:
		During the quarter ended March 31, 2003, we furnished the following Form 8-K reports:
		•    Current Report on Form 8-K furnished on February 21, 2003 (dated February 21, 2003) announcing financial results for the year ended December 31, 2002.
		•    Current Report on Form 8-K furnished on February 21, 2003 (dated February 21, 2003) detailing operational projections for the year ending December 31, 2003.

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

	WESTERN GAS RESOURCES, INC.
	(Registrant)
Date: May 14, 2003	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President
Date: May 14, 2003	By:	/s/WILLIAM J. KRYSIAK
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

	WESTERN GAS RESOURCES, INC.
	(Registrant)
Date: May 14, 2003	By:
		Peter A. Dea
		Chief Executive Officer and President
Date: May 14, 2003	By:
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

 

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CERTIFICATION

 

I, Peter A. Dea, certify that:
1.		I have reviewed this quarterly report on Form 10-Q of Western Gas Resources, Inc.;
2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
		a)      designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
		b)      evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
		c)      presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.		The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
		a)        all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
		b)        any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6.		The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

 

Dated: May 14, 2003
		/s/ Peter A. Dea
		Peter A. Dea
		Chief Executive Officer and President

 

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CERTIFICATION

 

I, William J. Krysiak, certify that:
1.		I have reviewed this quarterly report on Form 10-Q of Western Gas Resources, Inc.;
2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4.		The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
		a)        designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
		b)        evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
		c)        presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.		The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
		a)        all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
		b)        any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6.		The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

 

Dated: May 14, 2003
	/s/ William J. Krysiak
	William J. Krysiak
	Executive Vice President and Chief Financial Officer

 

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INDEX TO EXHIBITS

 

Exhibit Number		Description
3.1		Certificate of Incorporation of Western Gas Resources, Inc.  (Filed as exhibit 3.1 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2		Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc.  (Filed as exhibit 3.2 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3		Certificate of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock of the Company.  (Filed as exhibit 3.5 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-43077 dated November 14, 1991 and incorporated herein by reference).
3.5		Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on April 7, 2003.
10.1		Tenth Amendment, dated January 3, 2003, to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and Bank of America, N.A., as agent, and the Lenders (previously filed as Exhibit 10.28 to our 2002 Annual Report on Form 10-K and incorporated herein by reference).
10.2		Credit Agreement, dated as of April 24, 2003, among Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Bank One, NA and Fleet National Bank, as Co-Syndication Agents, The Royal Bank of Scotland plc and Wachovia Bank, National Association, as Co-Documentation Agents, and the Other Lenders Party Thereto.
10.3		Intercreditor Agreement, dated as of April 24, 2003, by and among the banks (as defined therein), Bank of America, N.A., as Administrative Agent for the banks and The Prudential Insurance Company of America, Pruco Life Insurance Company, ING Life Insurance & Annuity Company and Prudential Investment Management, Inc., consented to agreed by Western Gas Resources, Inc. and its subsidiaries listed therein.
10.4		Third Amended and Restated Master Shelf Agreement, dated as of December 19, 1991 (effective as of January 13, 2003), by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management Company, Inc. and ING Life Insurance & Annuity Company (filed as Exhibit 10.29 to our 2002 Annual Report on Form 10-K and incorporated herein by reference).
10.5		Letter Amendment No. 1 to Third Amended and Restated Master Shelf Agreement, dated as of April 24, 2003, by and among Western Gas Resources, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc. and ING Life Insurance & Annuity Company.
99		Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.

 

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